A seismic survey represents an attempt to map the subsurface of the earth by sending sound energy down into the ground and recording the "echoes" that return from the rock layers below. The source of the down-going sound energy might come, for example, from explosions or seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is moved to various positions across the surface of the earth above a geological structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at a great many locations on the surface. Multiple source/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2D) seismic survey, the recording locations are generally laid out along a single straight line, whereas in a three dimensional (3D) survey the recording locations are distributed across the surface in a grid pattern. In simplest terms, a 2D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3D survey produces a data "cube" or volume that is, at least conceptually, a 3D picture of the subsurface that lies beneath the survey area. In reality, though, both methods interrogate some volume of the earth lying beneath the area covered by the survey.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2D survey, there will usually be several tens of thousands of traces, whereas in a 3D survey the number of individual traces may run into the multiple millions of traces. The term "unstacked" seismic traces is used by those skilled in the art to describe seismic traces as they are collected in field recordings. This term also is applied to seismic traces during the processing sequence up to the point where traces are "stacked" or averaged together after first being corrected for timing differences. General background information pertaining 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of SEISMIC DATA PROCESSING by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, the disclosure of which is incorporated herein by reference. Chapter 1, pages 9 to 89, of Yilmaz contains general information relating to conventional 2D processing and that disclosure is also incorporated herein by reference.
A modern seismic trace is a digital recording (analog recordings were used in the past) of the energy reflecting back from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the elastic properties of the subsurface materials. The digital samples are usually acquired at 0.002 second (2 millisecond or "ms") intervals, although 4 millisecond and 1 millisecond sampling intervals are also common. Thus, each digital sample in a seismic trace is associated with a travel time (in the case of reflected energy, a two-way travel time from the surface to the reflector and back to the surface again). Further, the surface location of each trace in a seismic survey is carefully recorded and remains associated with that trace during subsequent processing. This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for posting and contouring seismic data--and attributes extracted therefrom--on a map (i.e., "mapping").
The data in a 3D survey are amenable to viewing in a number of different ways. First, horizontal "constant time slices" may be extracted from a stacked or unstacked seismic volume by collecting all of the digital samples that occur at the same travel time. This operation results in a 2D plane of seismic data. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2D seismic section from within the 3D data volume.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, unconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface rock velocities are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation subsequently applied to seismic data collected over other exploration targets.
Speaking in broad generalities, seismic energy propagates through the earth in one of two forms: compressional or "P" waves and shear or "S" waves, either of which might be generated by a wide variety of seismic sources. "Converted waves" travel first as one type of wave and then the other, the conversion between wave-types happening at any seismic discontinuity. If the conversion, from an incident P-wave to a reflected S-wave, happens at the reflector, this reflection mode will be called a C-wave.
Anisotropic media are those in which the P and S velocities depend upon the direction of wave propagation and of polarization. In anisotropic media, each conversion will in general reflect both fast and slow shear waves, which modes may be termed fast and slow C-modes. Flat-lying polar anisotropic ("VTI") layers give rise to only one C-mode (polarized in-line) reflection. For general information pertaining to anisotropy in the context of geophysical exploration, see Thomsen, "Weak elastic anisotropy", Geophysics, v. 51, no. 10, 1986, pp. 1954-1966, the disclosure of which is incorporated herein by reference.
Shear waves have vector displacements in the plane at approximately right angles to the raypath or direction of propagation and travel with a velocity dependent on the shear rigidity of the medium. Thus, shear waves contain different information about the subsurface structure along the raypath than do P-waves. Shear waves do not propagate through fluids, as fluids lack the stiffness necessary to support their passage. General background information on shear waves can be found, for example, in Helbig's article "Shear-Waves--What They Are and How They Can Be Used," in SHEAR-WAVE EXPLORATION, 1986, Danbom and Domenico, eds., pp. 19-36, the disclosure of which is incorporated herein by reference.
A shear wave propagating through an anisotropic medium generally splits into two phases with the fixed polarizations and fixed velocities that propagate in that particular direction. The medium establishes two orthogonal directions of polarization (for each direction of shear wave propagation), with each polarization potentially having a different shear wave velocity (i.e., "fast" and "slow" polarizations). These special directions may be related to the "principle coordinate axes" of the medium. Of course, in general the orientation of the principle coordinate axes is unknown (before the collection and processing of the seismic data), and must be determined from the data. Note that the orientation of the source does not have any effect upon the polarization axes, except that the source orientation determines how much energy is partitioned into each of the two polarization modes. General background information on shear-wave splitting in the exploration context may be found in Thomsen "Reflection seismology over azimuthally anisotropic media", Geophysics, v. 53, no. 3, 1988, pp. 304-131, the disclosure of which is incorporated herein by reference.
Since shear waves travel slower than P waves through the same medium, a "normal move out" correction ("NMO" correction, hereinafter) at P velocities leaves a good deal of residual moveout in shear events, which causes them to be attenuated in a conventional common midpoint ("CMP") stack. However, here are many exploration and exploitation settings wherein one would wish to preserve--rather than to suppress--converted-wave arrivals. For example, consider a hydrocarbon reservoir, above which the overburden contains a small concentration of gas. This gas will severely attenuate conventional P-waves traveling through this overburden, so that the underlying reservoir will be poorly imaged on a "P" section. However, since the gas-filled rock unit does not attenuate shear waves, one would expect to be able to obtain better images of such reservoirs using conventional pure-mode S-wave techniques. If the prospect lies under water, then the same logic predicts that converted-wave techniques may be successful.
Conventional seismic processing relies heavily on a stack (or time-corrected average) of seismic traces from a CMP gather to reduce coherent and incoherent noise in the seismic section, and as a tool for estimating subsurface velocities (through a velocity-dependent travel-time correction that is applied prior to the averaging). The stacking approach is generally satisfactory for single mode seismic data, but requires modification when applied to converted mode data. One reason for this is that the travel path of a converted mode wave is asymmetrical, even for simple horizontally layered media. Multiple coverage of the same subsurface point cannot be achieved for C-mode data by stacking a CMP gather, but instead requires the formation of a true common reflection point ("CRP", hereinafter) sorting which, for C-mode reflections, is actually a common conversion point gather (a "CCP" gather, hereinafter). In brief, the standard methods used to form converted mode CCP gathers in the past have been generally unsatisfactory.
One method for properly constructing a CCP gather is given in Thomsen, U.S. Provisional Patent Application No. 60/082,251, filed Apr. 17, 1998, the disclosure of which is incorporated herein by reference. By way of brief summary, in that reference the inventor teaches that the preferred method of constructing such a gather is founded on an initial determination (or assumption) that the converted-wave arrivals of interest are converted from P to S at a subsurface reflector, rather than at some other point on the raypath. In that case, the offset (from the source) of each conversion/reflection point may be separately calculated for each source-receiver pair, and for each arrival time, using the methods given therein. Finally, a flattened CCP gather is computed for each of a dense set of discrete positions (x.sub.c, y.sub.c) on the same surface, which surface represents, at every reflection time, converted-wave energy arriving from some source-receiver pair (as calculated above), and the surface bin represented by that CCP point is converted. This is done separately for each component of the recorded signal, using the same velocity for each.
Multi-component seismic surveys use a combination of receiver types to record the returning seismic energy. Typically there will be three directional receivers at each recording location: a vertical geophone and two horizontal geophones. Each of these receivers are designed to translate motion on the surface of the earth into an electrical signal representative of the amplitude and frequency of the motion. The vertical component is usually some variant of a conventional seismic receiver that is sensitive to vertical ground motion. There may also be a hydrophone at each recording location, but that variation will not be discussed here. There are usually two horizontal receivers at each recording site, each of which is sensitive to horizontal ground motion along a single axis of movement. By convention, the two horizontal receivers are usually deployed at right angles to each other so that horizontal ground motion along any axis can be effectively detected. Of course, ground motion that exhibits horizontal displacement in a direction that is not in exact alignment with the axis of movement of either of the horizontal detectors will have energy appearing on both of the horizontal detectors. Standard 2D methods are available to those skilled in the art (e.g., "rotation") for reconstructing the magnitude and direction of horizontal ground motion from the two shear signals e.g., see Thomsen, 1988, "Method of seismic exploration including processing and displaying shear wave seismic data", U.S. Pat. No. 4,755,972, Alford, 1994, "Multisource Multireceiver Method and System for Geophysical Exploration", U.S. Pat. No. 5,343,441, the disclosures of which are incorporated herein by reference). See also Thomsen, 1988, "Reflection seismology over azimuthally anisotropic media", cited previously.
By convention, it is usually assumed that the response of the receiver components is equal for equal ground displacements in the various axial directions, i.e., that the recording has "vector fidelity." If the instrument does not at least approximately meet this assumption, the recording should be corrected before the vector operations--such as those described hereinafter--are applied.
In current state-of-the-art converted wave processing schemes, the assumption is usually made that the earth through which the seismic signal passes is azimuthally isotropic (i.e., either completely isotropic, or perhaps polar isotropic with a vertical symmetry axis) and the reflectors are flat lying. In such a case (see, for example, Aki, K. and P. G. Richards, 1981, QUANTITATIVE SEISMOLOGY, Freeman Press, N.Y.), the upcoming shear wave will be polarized in the vertical plane containing the source and the receiver. Hence, during processing each 2-component (x, y) shear record is mathematically rotated about a vertical axis so that one of the new coordinates axes (say, x') is aligned to be parallel to the source-receiver direction. If the instrument records the ground motion with true vector fidelity, this rotation operation results in a seismic trace (x') that contains the signal that would have been recorded if one horizontal component of the receiver had been parallel to the source-receiver direction when the source was excited. After rotation, these "radial" x' traces can be processed--for the most part--as through they were part of a standard CRP gather. The other seismic trace that emerges from the rotation--i.e., the y' or transverse trace--is typically ignored, since by conventional wisdom it should be "null" and contain only noise, since all of the coherent seismic energy is supposed to have been moved to the x' trace by the rotation process.
However, in practice one typically finds that the component (y')transverse to the source-receiver direction (x'), is typically not null, but instead contains data, often comparable in strength to that on the x' component itself. This may happen for a number of reasons, but in flat-lying geometry the most plausible cause is azimuthal anisotropy of the medium. It is well known (see, for example, Thomsen, 1988, cited previously) that, in such cases, the polarization is determined by the medium, rather than by the source (as in the isotropic case discussed previously).
When multi-component shear wave data from such media are recorded, each component will normally contain contributions from both fast and slow shear modes. It is usually necessary and/or desirable to separate these two modes, since without such separation, they interfere with each other, making interpretation difficult. Additionally, traces containing the combined modes cannot easily be processed and stacked, as each trace contains some combination of slow and fast events which may occur at the time travel time. However, knowledge of the angular orientation of the principal axes of the subsurface medium is a prerequisite to doing this separation. Thus, one of the greatest challenges facing interpreters and explorationists is that of deducing the orientations of the principal axes of a 3D converted wave survey, so the principal times series can be determined. 3-D seismic surveys--and some 2-D crooked line surveys--present an additional challenge to the processing geophysicist. As is well known to those skilled in the art, each CCP "bin" in such a survey consists of a small area (usually a few meters on each side) beneath which are the reflection points of a number of unstacked traces, each potentially collected at a different source-receiver azimuth. Thus, there is no single survey azimuth angle that can be used to rotate all of the traces in a bin into alignment with the principal axes: each trace must be separately rotated to a common heading. Note that, each source-receiver azimuth may be thought of as a separate interrogation of the unknown orientation of the subsurface anisotropy, and each recorded trace contains potentially unique information about the unknown subsurface fracture orientation. Alford 1994, cited previously, teaches the most common method of deducing this information from 3D or 2D land surveys, in which the sources are polarized horizontally and excite shear waves directly in each of two orthogonal orientations. However, there has been, in the past, no systematic way of using this multiplicity of information to estimate the subsurface principal axes for converted wave surveys.
A variety of ad hoc approaches to solving the aforementioned 3-D converted wave problem have been suggested. For example, Garotta and Granger ("Acquisition and processing of 3C.times.3D data using converted waves", Soc. Expl. Geoph. Expanded Absts, 58, 995-997 (1988)), the disclosure of which is incorporated herein by reference, divide the CCP gathers (taken from bins of a 3D survey) into restricted-azimuth subsets, and compare the energy found on the radial component with that on the transverse component. The mid-angle from each restricted range-of-azimuths becomes a candidate for the rotation angle .THETA..sub.0, with the mid-angle for which the transverse energy was minimal within a computation time-window ultimately being selected as .THETA..sub.0, where .THETA..sub.0 represents the angular difference between the survey coordinate system and the underlying anisotropy orientation. However, this method suffers from an implicit assumption that the distribution of offsets (and, hence, the conversion efficiency) within each restricted-azimuth subset is the same or comparable, and it additionally suffers from a certain arbitrariness in the choice of the range of the azimuthal restrictions.
More recently, Gaiser ("3D converted shear wave rotation with layer stripping", U.S. Pat. 5,610,875, the disclosure of which is incorporated herein by reference) revisited Alford's original approach, using 3D data collected into bins, but without stacking. However, this method requires that the gather be composed of CCP-pairs arising from matched sets of sources and receivers which are mutually orthogonal and of equal offset (hence equal conversion efficiency). This restriction is not normally met in practice.
So, as was recognized by the present inventor, there continues to be a need for a method of determining the axes of orientation of a subsurface medium from seismic data consisting of source-receiver pairs collected at a variety of different azimuths. Further--and this is especially true in the case of a multicomponent 3D seismic survey--this determination should be made for each CCP bin and at each depth. The method should be statistically based and should employ the entire data-set in each bin, so as to overcome the shortcomings of the prior art discussed previously. Finally, the method should yield good estimates of the axes of orientation for use in subsequent seismic processing.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or preferred embodiments) shown and described. This is so because those skilled in the art to which the invention pertains will be able to devise other forms of this invention within the ambit of the appended claims.